Coal Fired Steam Plants - PDHonline.comThe coal is crushed between balls or cylindrical rollers that move between two tracks or "races." The raw coal is then fed into the pulverizer

An Approved Continuing Education Provider

PDHonline Course E347 (4 PDH)

Coal Fired Steam Plants

Instructor: Lee Layton, P.E

2020

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Coal Fired Steam Plants

Table of Contents

Section Page

Introduction ……………………………………. 3

Chapter 1 – Coal as a Fuel Source………………. 5

Chapter 2 – Coal-Fired Steam Plant Designs …. 15

Chapter 3 – Environmental Issues ……………. 31

Summary ……………………………………… 39

Cover photograph is provided courtesy of the Tennessee Valley Authority (TVA)





Introduction

For over 100 years coal fired power plants have provided a stable source of electricity that

provides vast quantities of inexpensive, reliable power. Historically, coal-fired generation gas

accounted for over 50% of the electricity generated in the U.S. The generation mix has been

changing in recent years due to low-cost natural gas and some impact from renewable energy

sources. Presently coal is less around 30% of the total fuel mix with natural gas the pre-

dominate source at 34%. The known coal reserves are expected to last for centuries at the

current rates of usage. See Figure 1 for a breakdown of electricity generation by fuel type.

Coal power is a rather simple process. In

most coal fired power plants, chunks of coal

are crushed into fine powder and are fed into

a combustion unit where it is burned. Heat

from the burning coal is used to generate

steam that is used to spin one or more

turbines to generate electricity.

Coal has played a major role in electrical

production since the first power plants that

were built in the United States in the 1880's.

The earliest power plants used hand fed coal

to heat a boiler and produce steam. This

steam was used in reciprocating steam

engines which turned generators to produce

electricity. In 1884, the more efficient high

speed steam turbine was developed which

replaced the use of steam engines to generate

electricity. In the 1920s, the pulverized coal firing was developed. This process brought

advantages that included a higher combustion temperature, improved thermal efficiency and a

lower requirement for excess air for combustion. In the 1940s, the cyclone furnace was

developed. This new technology allowed the combustion of poorer grade of coal with less ash

production and greater overall efficiency.

Coal is pulverized into a fine powder stems because, if the coal is made fine enough, it will burn

almost as easily and efficiently as a gas. The coal is crushed between balls or cylindrical rollers

that move between two tracks or "races." The raw coal is then fed into the pulverizer along with

air heated from the boiler. As the coal gets crushed by the rolling action, the hot air dries it and

blows the usable fine coal powder out to be used as fuel. The powdered coal from the pulverizer

Figure 1





is directly blown to a burner in the boiler. The burner mixes the powdered coal in the air

suspension with additional pre-heated combustion air and forces it out of a nozzle. Under

operating conditions, there is enough heat in the combustion zone to ignite all the incoming fuel.

Cyclone furnaces were developed after

pulverized coal systems and require less

processing of the coal fuel. They can burn

poorer grade coals with higher moisture

contents and ash contents. The crushed coal

feed is either stored temporarily in bins or

transported directly to the cyclone furnace. The

furnace is basically a large cylinder jacketed

with water pipes that absorb the some of the

heat to make steam and protect the burner itself

from melting down. A high powered fan blows

the heated air and chunks of coal into one end of the cylinder. At the same time additional heated

combustion air is injected along the curved surface of the cylinder causing the coal and air

mixture to swirl in a centrifugal "cyclone" motion. The whirling of the air and coal enhances the

burning.

Coal-fired technology has improved the heat rates of coal plants from over 138,000 BTU/kWh in

the 1880’s to less than 10,000 BTU/kWh today.

We will start this course with an overview of the coal industry followed by a detailed explanation

of the components of a coal-fired steam plant and we will conclude with a look at the

environmental issues associated with a coal-fired steam plant.





Chapter 1

Coal as a Fuel Source

Coal is a fossil fuel formed from plant remains that were preserved by water and mud from

biodegradation. Coal is a readily combustible black or brownish-black rock. It is composed

primarily of carbon and hydrogen along with small quantities of other elements, notably sulfur.

Coal is extracted from the ground by coal mining, either underground mining or open pit mining.

Coal is the largest source of fuel for the generation

of electricity world-wide and is the largest natural

energy source in the United States. Coal is also

the largest world-wide source of carbon dioxide

emissions and it may be contributing to climate

change and global warming. In terms of carbon

dioxide emissions, coal is slightly ahead of

petroleum and about double that of natural gas.

Coal has been used as a fuel source for thousands

of years; the Chinese mined coal stone for fuel

10,000 years ago at the time of the New Stone Age. The development of the Industrial

Revolution led to the large-scale use of coal, as the steam engine took over from the water wheel

as the prime mover in industrial plants.

Coal is primarily used as a solid fuel to produce electricity and heat through combustion. World

coal consumption is about 6.2 billion tons annually, of which about 75% is used for the

production of electricity.

When coal is used for electricity generation, it is usually pulverized and then burned in a furnace

with a boiler. The furnace heat converts boiler water to steam, which is then used to spin

turbines which turn generators and create electricity. The thermodynamic efficiency of this

process has been improved over time. Traditional steam turbines have topped out with some of

the most advanced units reaching about 35% thermodynamic efficiency for the entire process,

which means 65% of the coal energy is waste heat that is released into the surrounding

environment. Older coal power plants are significantly less efficient and produce higher levels of

waste heat.

Approximately 40% of the world electricity production uses coal. It is estimated that the total

known coal deposits recoverable by current technologies might be sufficient for around 250-300

years' use at current consumption levels.





Types of Coal

We use the term "coal" to describe a variety of fossilized plant materials, but no two coals are

exactly alike. Heating value, ash melting temperature, sulfur and other impurities, mechanical

strength, and many other chemical and physical properties must be considered when matching

specific coals to a particular application.

Coal is classified into four general categories, or "ranks." They range from lignite through sub-

bituminous and bituminous to anthracite, reflecting the progressive response of individual

deposits of coal to increasing heat and pressure. The carbon content of coal supplies most of its

heating value, but other factors also influence the amount of energy it contains per unit of

weight. (The amount of energy in coal is expressed in British thermal units per pound. A BTU is

the amount of heat required to raise the temperature of one pound of water one degree

Fahrenheit.)

About 90 percent of the coal in the U.S. falls in the bituminous and sub-bituminous categories,

which rank below anthracite and, for the most part, contain less energy per unit of weight.

Bituminous coal predominates in the Eastern and Mid-continent coal fields, while sub-

bituminous coal is generally found in the Western states and Alaska. Lignite ranks the lowest and

is the youngest of the coals. Most lignite is mined in Texas, but large deposits also are found in

Montana, North Dakota, and some Gulf Coast states.

Anthracite

Anthracite is coal with the highest carbon content, between 86 and 98 percent, and a heat value

of nearly 15,000 BTUs-per-pound. Most frequently associated with home heating, anthracite is a

very small segment of the U.S. coal market. There are 7.3 billion tons of anthracite reserves in

the United States, found mostly in 11 northeastern counties in Pennsylvania.

Bituminous

The most plentiful form of coal in the United States, bituminous coal is used primarily to

generate electricity and make coke for the steel industry. The fastest growing market for coal is

supplying heat for industrial processes. Bituminous coal has a carbon content ranging from 45 to

86 percent carbon and a heat value of 10,500 to 15,500 BTUs-per-pound. The carbon content of

bituminous coal is around 60-80%; the rest is composed of water, air, hydrogen, and sulfur.

Bituminous coal is a relatively soft coal containing a tarlike substance called bitumen. It is of

higher quality than lignite coal but poorer quality than anthracite coal.

Bituminous coal is usually black, sometimes dark brown, often with well-defined bands of bright

and dull material. Bituminous coal seams are identified by the distinctive sequence of bright and





dark bands and are classified accordingly as either "dull, bright-banded" or "bright, dull-banded"

and so on.

Bituminous coals are graded according to reflectance, moisture content, volatile content,

plasticity and ash content. Generally, the highest value bituminous coals are those which have a

specific grade of plasticity, volatility and low ash content, especially with low carbonate,

phosphorus and sulfur.

Plasticity is vital for coking as it represents its ability to gradually form specific plasticity phases

during the coking process. Low phosphorus content is vital for these coals, as phosphorus is

detrimental to steel making.

Coking coal is best if it has a very narrow range of volatility and plasticity. Volatile content and

swelling index are used to select coals for coke blending as well.

Volatility is also critical for steel-making and power generation, as this determines the burn rate

of the coal. High volatile content coals, while easy to ignite often are not as prized as moderately

volatile coals; low volatile coal may be difficult to ignite although it will contain more energy

per unit volume. The smelter must balance the volatile content of the coals to optimize the ease

of ignition, burn rate, and energy output of the coal.

Low ash, sulfur, and carbonate coals are good choices for power generation because they do not

produce much boiler slag and they do not require as much effort to scrub the flue gases to

remove particulate matter. Carbonates are detrimental to the boiler apparatus because they stick

to the equipment. Sulfide contents are also detrimental to some degree as this sulfur is emitted

and can form smog, acid rain and haze pollution. Scrubbers on the flue gases are used to

eliminate particulate and sulfur emissions.

When used for industrial processes, bituminous coal must first be "coked" to remove volatile

components. Coking is achieved by heating the coal in the absence of oxygen, which drives off

volatile hydrocarbons such as propane, benzene and other aromatic hydrocarbons, and some

sulfur gases. This also drives off the amount of the contained water of the bituminous coal.

Coking coal is used in the manufacture of steel, where carbon must be as volatile-free and ash-

free as possible.

Bituminous coal is mined in the Appalachian region, primarily for power generation. Mining is

done via both surface and underground mines.





Sub-bituminous

Ranking below bituminous is sub-bituminous coal with 35-45 percent carbon content and a heat

value between 8,300 and 13,000 BTUs-per-pound. Reserves are located mainly in a half-dozen

Western states and Alaska. Although its heat value is lower, this coal generally has a lower sulfur

content than other types, which makes it attractive for use because it is cleaner burning.

Sub-bituminous coal is a type of coal whose properties range from those of lignite to those of

bituminous coal and is used primarily as fuel for steam-electric power generation.

Sub-bituminous coal may be dull, dark brown to black, soft and crumbly at the lower end of the

range, to bright, jet-black, hard, and relatively strong at the upper end. It contains 20-30%

inherent moisture by weight. A major source of sub-bituminous coal in the United States is the

Powder River Basin in Wyoming.

Its relatively low density and high water content renders some types of sub-bituminous coal

susceptible to spontaneous combustion if not packed densely during storage in order to exclude

free air flow.

Lignite

Lignite is a geologically young coal which has the lowest carbon content, 25-35 percent, and a

heat value ranging between 4,000 and 8,300 BTUs-per-pound. Sometimes called brown coal, it

is mainly used for electric power generation.

It is the lowest rank of coal and used almost exclusively as fuel for steam-electric power

generation. It is brownish-black and has a high inherent moisture content, sometimes as high as

66%, and very high ash (50%) content compared with bituminous coal. It is also a

heterogeneous mixture of compounds for which no single structural formula will suffice.

Because of its low energy density, brown coal is inefficient to transport and is not traded

extensively on the world market compared with higher coal grades. It is often burned in power

stations constructed very close to any mines. Carbon dioxide emissions from brown coal fired

plants are generally much higher than for comparable black coal plants.

Lignite can be separated into two types. The first is fossil wood and the second form is the

compact lignite or perfect lignite. Fossil wood is barely classified as coal and is a very marginal

coal feedstock with a heat rate of less than 6,300 BTU’s. While still an inefficient coal, compact

lignite has a heat rate of greater than 6,300 BTU’s.





Energy density

The energy density of coal can be expressed in kilowatt-hours per pound (kWh/lb) of coal. The

energy density of coal is about 3 kWh/lb of coal. When you consider that the thermal efficiency

of a coal-fired power plant is about 30% then the only about 0.91 kWh’s are produced for each

pound of coal burned. The remainder is given up as waste heat and other losses in the generation

process. Said another way, it takes about 1.1 pounds of coal to generate one kWh. Each

kilowatt-hour produced also generates about 2 pounds of CO2.

To put this in laymen’s terms, consider the energy required to light a 100-watt incandescent light

bulb for one year assuming 4-hours use per day. It will require 146 kWh’s per year (100 * 4 *

365 / 1,000 = 146) to light the lamp for four hours per day for one year. Since it takes 1.1

pounds of coal per kWh, 160 pounds of coal will be required and almost 300 pounds of CO2 will

be generated. In comparison, an equivalent compact fluorescent lamp is only 23 watts and will

only use 34 kWh’s per year, 37 pounds of coal, and about 70 pounds of CO2.

Another interesting comparison is the CO2 generated from coal versus other sources. As we

mentioned, coal-fired generation results in about 2 lbs/kWh of CO2. For oil-fired generation it is

slightly less than 2 lbs/kWh and for natural gas, the CO2 emissions are about 1.1 lbs/kWh. For

nuclear power, the CO2 are miniscule, perhaps 0.1 lbs/kWh.

World coal reserves

The recoverable coal reserves are estimated to be around 900 billion tons. This is equal to about

4,417 billion barrels of oil equivalent (BBOE). The annual coal consumption is about 46 million

barrels of oil or 17 BBOE. If consumption continues at this rate the reserves will last 260 years.

As a comparison, natural gas provides 51 million BOE and oil provides 76 million barrels per

day.

United States Coal Reserves

Of the three fossil fuels, coal has the most widely distributed reserves; coal is mined in over 100

countries, and on all continents except Antarctica. The largest reserves are found in the United

States, Russia, Australia, China, India and South Africa. In the continental United States, the

coal largest reserves are divided into eleven geographic regions. They are,

1. Northern Appalachian

2. Central Appalachian

3. Southern Appalachian





4. Gulf

5. Illinois Basin

6. Western Interior

7. Plains (also called North Dakota Lignite)

8. Powder River Basin

9. Rockies

10. Southwest

11. Northwest

The following graphic shows the supply and percent of the U.S. coal reserves by region.

As you can see from the chart, the Powder River Basin, North Appalachian, and Central

Appalachian coal make up the bulk of the U.S. coal reserves. Figure 2 on the next page shows

each of these regions on a map of the United States.





The following is a discussion of a few of the major coal areas in the country.

Northern Appalachian

Coal from the Northern Appalachian region is predominately bituminous. It includes the states

of Pennsylvania, Ohio, Maryland, and portion of West Virginia. About 60% of Northern

Appalachian coal comes from the Pittsburgh seam, which is a large reserve of coal that runs

throughout the area.

Central Appalachian

Central Appalachian coal is low sulfur bituminous coal. This region includes portions of

Kentucky, West Virginia, Virginia, and Tennessee. Because of the low sulfur content of Central

Appalachian coal it has been widely used in power plants that have not been retrofitted with

pollution control scrubbers. Coal from this region tends to run in narrow seams and mines are

exhausted quickly, requiring new mines to be built. The area has been mined extensively and

finding new areas to mine, and getting them permitted is getting more difficult.









Southern Appalachian

Alabama and Tennessee make up the Southern Appalachian coal region. This is an area of

bituminous coal.

Gulf Coast

The Gulf coast covers a wide swath of Southern states including Texas, Louisiana, Arkansas,

Mississippi, Northern Florida, and Alabama. This is an area of lignite and was used for many

years for power production. Many of the sources are nearing depletion, but the area has an

abundance of untapped reserves. Many IGCC plants are considering Gulf lignite as a feedstock.

Illinois Basin

The states of Illinois, Indiana, and Western Kentucky comprise most of the Illinois Basin. The

Illinois Basin is an area of bituminous coal that is relatively high in sulfur content. However,

there are a few low sulfur areas in the Illinois Basin. This area has not been extensively mined

and large reserves exist, especially of high sulfur content coal.

Western Interior

The six states of Arkansas, Oklahoma, Kansas, Missouri, Nebraska, and Iowa make up the

Western Interior coal area. This area is predominately bituminous coal. The area is comprised

of three major basins and has significant coal reserves.

Powder River Basin

The Power River Basin (PRB) includes Northern Wyoming and Southeast Montana. It is a large

area of sub-bituminous coal. It has the advantage of being easy to access from surface mines and

has relatively thick seams and is a low sulfur coal. The disadvantage is that the PRB is not near

major load centers and the coal must be transported long distances to the power plants.

Table 1 has the characteristics of a few of the coal from four of the regions.





Table 1

Comparison of Coal Characteristics by Region

(by percent, except BTU values)

Properties Appalachian Illinois Basin Powder River

Basin Gulf Coast

Moisture 5.20 12.20 30.24 26.80

Carbon 73.80 61.00 48.18 45.82

Hydrogen 4.90 4.25 3.31 3.11

Nitrogen 1.40 1.25 0.70 0.70

Chlorine 0.07 0.07 0.01 n/a

Sulfur 2.13 3.28 0.37 0.69

Oxygen 5.40 11.00 11.87 14.68

Ash 7.10 6.95 5.32 8.20

Heat Content (BTU) 13,260 10,982 8,340 7,810

From Table 1 we see that the Appalachian coal has the highest BTU value with a sulfur content

of slightly over 2%. In comparison, the Powder River Basin coal has a much lower BTU content

(8,340), but has a sulfur content of only 0.37% while the Illinois Basin coal has a moderately

good BTU content of 10,982 and very high sulfur content at over 3%.





Chapter 2

Coal-Fired Steam Plant Designs

Coal-fired steam plants are designed on a large scale for continuous operation. These plants

have some kind of rotating machinery to convert the heat energy of combustion into mechanical

energy, which then operate an electrical generator. The prime mover is a steam turbine. The

plants operate on the principal of the drop between the high pressure and temperature of the

steam and the lower pressure of the atmosphere or condensing vapor in the steam turbine.

In a coal-fired power plant the chemical energy

stored in the coal and oxygen of the air is converted

successively into thermal energy, mechanical energy

and, finally, electrical energy for continuous use and

distribution across a wide geographic area. Each

fossil fuel power plant is a highly complex, custom-

designed system. Multiple generating units may be

built at a single site for more efficient use of land,

natural resources and labor.

Coal fired power plants produce waste. These byproducts must be considered in both the design

and operation of the plants. Waste heat due to the finite efficiency of the power cycle must be

released to the atmosphere, often using a cooling tower, or river or lake water as a cooling

medium, especially for condensing steam. The flue gas from combustion of the fossil fuels is

discharged to the air; this contains carbon dioxide and water vapor, as well as other substances

such as nitrogen, nitrogen oxides, sulfur oxides, fly ash, and mercury. Solid waste ash from

coal-fired boilers must also be removed, although some coal ash is recycled for building

materials.

A coal plant is classified by its operating temperature and pressure. The three basic

configurations are,

1. Sub-critical steam plants

2. Super-critical steam plants

3. Ultra-super-critical steam plants

Early coal-fired steam plants heated water to a boil to produce steam to run the turbines. These

plants, many which are still in operation today, are called sub-critical plants and operate at

pressures of around 2,500 psi. At this pressure, as water is heated it will beginning boiling and

then transition to steam. Sub-critical fossil fuel power plants can achieve efficiencies of 36–

40%.





Modern coal plants are known as Super-critical plants and operate about the critical point for

water, which is 374C and 3,212 psi. Above this temperature and pressure, there is no phase

transition from water to steam, but only a gradual decrease in density. Super-critical designs

have efficiencies in the low to mid 40% range. Since boiling does not occur it is not possible to

remove impurities via steam separation. A supercritical steam plant utilizes the increased

thermodynamic efficiency of operating at higher temperatures. These plants, also called once-

through plants because boiler water does not circulate multiple times, require additional water

purification steps to ensure that any impurities picked up during the cycle will be removed. This

purification takes the form of high pressure ion exchange units called condensate polishers

between the steam condenser and the feedwater heaters.

The newest form of coal-fired steam plants are called ultra-super-critical steam plants and

operate at pressures of 4,400 psi and temperatures in excess of 600C. These units can reach

efficiencies of 48%. Naturally the increase in efficiency reduces the amount of coal that must be

burned to generate electricity, so these units have an immediate environmental benefit. These

can also take advantage of lower BTU fuel such as Powder River Basin coal. Ultra-super-critical

plants are made possible by advancements in metallurgy, such as the development of chrome and

nickel-based super alloys that can withstand high-temperatures and high-pressures.

See Figure 4 on the next page for a diagram of a typical coal-fired power plant. This figure will

be used to describe each of the major components of a coal-fired power plant. The description

that follows explains the process from coal entering the facility to the generation of electricity.









Looking at Figure 4, let’s follow the energy path through the plant. The numbers in parenthesis

match the numbers in the yellow boxes in Figure 4.

Coal is conveyed (14) from an external stack and ground to a very fine powder by large metal

spheres in the pulverized fuel mill (16). There it is mixed with preheated air (24) driven by the

forced draft fan (20).

The hot air-fuel mixture is forced at high pressure into the boiler where it rapidly ignites. Water

of a high purity flows vertically up the tube-lined walls of the boiler, where it turns into steam,

and is passed to the boiler drum, where steam is separated from any remaining water. The steam

passes through a manifold in the roof of the drum into the pendant superheater (19) where its

temperature and pressure increase rapidly to around 2,900 PSI and 570°C, sufficient to make the

tube walls glow a dull red.

The steam is piped to the high-pressure turbine (11), the first of a three-stage turbine process.

A steam governor valve (10) allows for both manual control of the turbine and automatic set

point following. The steam is exhausted from the high-pressure turbine, and reduced in both

pressure and temperature, and returned to the boiler reheater (21).

The reheated steam is then passed to the intermediate pressure turbine (9), and from there passed

directly to the low pressure turbine set (6). The exiting steam, now a little above its boiling

point, is brought into thermal contact with cold water (pumped in from the cooling tower) in the

condensor (8), where it condenses rapidly back into water, creating near vacuum-like conditions

inside the condensor chest.

The condensed water is then passed by a feed pump (7) through a deaerator (12), and pre-

warmed, first in a feed heater (13) and then in the economizer (23), before being returned to the

boiler drum.

The cooling water from the condensor is sprayed inside a cooling tower (1), creating a highly

visible plume of water vapor, before being pumped back to the condensor (8) in cooling water

cycle.

The three turbine sets are coupled on the same shaft as the three-phase electrical generator (5)

which generates an intermediate level voltage (typically 20-25 kV). This is stepped up by a

transformer (3) to a voltage more suitable for transmission (typically 250-500 kV) and is sent out

onto the three-phase transmission system (4).

Exhaust gas from the boiler is drawn by the induced draft fan (26) through an electrostatic

precipitator (25) and is then vented through the chimney stack (27).





Next, we will look at a few of the major components in a little more detail.

Fuel Transport and Delivery

Coal is delivered to the power plant by highway truck, rail, barge, or collier ship. Some plants

are built near coal mines and coal is delivered by conveyors. A large coal train called a unit train,

or rake, may be over a mile long, containing 100 cars with 100 tons of coal in each one, for a

total load of 10,000 tons. A large plant that is at full load operation requires at least one coal

delivery this size every day. Plants may get as many as three to five trains a day, especially in

high demand seasons.

A cargo ship carrying coal may hold 40,000

tons of coal and takes several days to unload.

Some ships carry their own conveying

equipment to unload their own bunkers; others

depend on equipment at the plant. For

transporting coal in calmer waters, such as

rivers and lakes, flat-bottomed barges are often

used.

The coal handling plant handles the coal from

its receipt at the power plant to transporting it

to boiler and storage in bunkers. It also

processes the raw coal to make it suitable for

boiler operation.

The coal handling plant involves receiving the

coal from coal mines, weighing of coal,

crushing it to required size and transferring it

to various coal mill bunkers.

At the plant site, some or all of the following

components may be found: Wagon tipplers,

vibrating feeders, conveyor belts, coal crushers, trippers, electromagnetic separators, dust

extraction systems, and gas extractors.

Wagon tipplers are the giant machines having gear boxes and motor assembly and are used to

unload the coal wagons into coal hoppers quickly. Vibrating feeders are electromagnetic

vibrating feeders or sometimes in the form of dragging chains which are provided below the coal





hoppers. This equipment is used for controlled removal of coal from coal hoppers. Conveyor

belts are the synthetic rubber belts which move on metallic rollers called idlers and are used for

shifting of coal from one place to other places. Coal crushers receive the coal in the form of odd

shaped lumps. These lumps are to be crushed to required size. These lumps are crushed by coal

crushers. Trippers are the motorized or manually operated machines and are used for feeding the

coal to different coal bunkers as per their requirement. Electromagnetic separators are used for

removing of Iron and magnetic impurities from the coal. Dust extraction systems are provided in

CHP for suppression of coal dust in coal handling plant. Gas extractors are provided at the

bunker level to remove all types of poisonous and non poisonous gases from the working area.

Modern unloaders use rotary dump devices, which eliminate problems with coal freezing in

bottom dump cars. The unloader includes a train positioner arm that pulls the entire train to

position each car over a coal hopper. The dumper clamps an individual car against a platform

that swivels the car upside down to dump the coal. Swiveling couplers enable the entire

operation to occur while the cars are still coupled together. Unloading a unit train takes about

three hours.

Shorter trains may use railcars with an air-dump, which relies on air pressure from the engine

plus a hot shoe on each car. This "hot shoe" when it comes into contact with a hot rail at the

unloading trestle, shoots an electric charge through the air dump apparatus and causes the doors

on the bottom of the car to open, dumping the coal through the opening in the trestle. Unloading

one of these trains takes anywhere from an hour to an hour and a half. Older unloaders may still

use manually operated bottom-dump rail cars and a "shaker" attached to dump the coal.

The normal operating cycle of a coal handling plant involves bunkering, stacking, and reclaiming

the coal. The normal bunkering cycle involves shifting the coal received from coal wagons

directly to coal bunkers. The stacking cycle is when there is no coal requirement at coal bunkers

the coal is received and stacked in the coal yard. When coal is removed from the stack for use it

is called the reclaiming cycle.

Once the coal is needed at the plant it is prepared for use by crushing the rough coal to pieces

less than two inches in size. The coal is then transported from the storage yard to in-plant storage

silos by rubberized conveyor belts.

In plants that burn pulverized coal, silos feed coal pulverizers that take the larger 2-inch pieces,

grind them to the consistency of powder, sort them, and mix them with primary combustion air

which transports the coal to the furnace and preheats the coal to drive off excess moisture

content.





In plants that do not burn pulverized coal, the larger pieces may be directly fed into the silos

which then feed the cyclone burners, which is a specific kind of combustor that can efficiently

burn larger pieces of fuel.

Routinely during the coal handling process, a sample of coal is randomly collected from each

rake and detailed chemical analysis, calculation of calorific value is carried out to confirm the

coal meets the contract specifications.

Boiler operation

The boiler in a typical steam plant is huge; typically a rectangular furnace about 50 feet on a side

and 130 feet tall. Its walls are made of a web of high pressure steel tubes.

Pulverized coal is air-blown into the furnace from fuel nozzles at the four corners and it rapidly

burns, forming a large fireball at the center. The thermal radiation of the fireball heats the water

that circulates through the boiler tubes near the boiler perimeter. The water circulation rate in the

boiler is three to four times the throughput and is typically driven by pumps. As the water in the

boiler circulates it absorbs heat and changes into steam at 374C and 3,212 psi. It is separated

from the water inside a drum at the top of the furnace. The saturated steam is introduced into

superheat pendant tubes that hang in the hottest part of the combustion gases as they exit the

furnace. Here the steam is superheated to prepare it for the turbine.

Steam turbine generator

A steam turbine uses a liquid that evaporates when heated and expands to produce work, such as

turning a turbine. The working fluid most commonly used is water, though other liquids can also

be used. The thermodynamic cycle for the steam turbine is the Rankine cycle. The cycle is the

basis for conventional power generating stations and consists of a boiler that converts water to

high pressure steam. The steam flows through the turbine to produce power. The steam exiting

the turbine is condensed and returned to the boiler to repeat the process.

The Rankine cycle is a four-stage process. In the first stage, the working fluid is pumped into a

boiler. While the fluid is in the boiler, an external heat source - in this case burning coal -

superheats the fluid. The hot water vapor then expands to drive a turbine. Once past the turbine,

the steam is condensed back into liquid and recycled back to the pump to start the cycle all over

again. Pump, boiler, turbine, and condenser are the four parts of a standard steam engine and

represent each phase of the Rankine cycle. The following figure is a schematic of a Rankine

cycle system.





The four processes in the Rankine cycle each change the state of the working fluid. See the

drawing in Figure 6 above.

In the first step the working fluid is pumped from low to high pressure, as the fluid is a liquid at

this stage the pump requires little input energy.

Next, the high pressure liquid enters a boiler where it is heated at constant pressure by an

external heat source to become a dry saturated vapor.

Passing through the boiler the dry saturated vapor expands through a turbine generating power

output usually orders of magnitude greater than the power required by the pump. This decreases

the temperature and pressure of the vapor and some condensation may occur.

In the final step, the wet vapor enters a condenser where it is cooled at a constant low pressure to

become a saturated liquid. It is fully condensed to a liquid to minimize the work required by the

pump.





In an ideal Rankine cycle, the compression by the pump and the expansion in the turbine would

be completely reversible and there would be no losses in the conversion. Of course, in the real

world the process does generate losses, which increases the power required by the pump and

decreases the power generated by the turbine.

In comparison to combustion turbines where a significant fraction of the work generated by the

turbine is required to drive the compressor, limiting net work output and efficiency, a Rankine

cycle requires very little power for ancillary needs. By condensing the steam to water, the work

required by the pump will only consume approximately 1% of the turbine power resulting in a

much higher efficiency. As liquids are far less compressible they require only a fraction of the

energy needed to compress a gas to the same pressure.

The efficiency of a Rankine cycle is usually limited by the working fluid. Without the pressure

going super critical the operating temperature range is quite small; turbine entry temperature is

typically 565C and condenser temperatures are around 30C. This gives a theoretical efficiency

of around 63% compared with an actual efficiency of 42% for a modern coal fired power plant.

The working fluid in a Rankine cycle follows a closed loop and is re-used constantly. The

efficiency of the steam turbine will be limited by water droplet formation. As the water

condenses, water droplets hit the turbine blades at high speed causing pitting and erosion,

gradually decreasing the efficiency of the turbine. The easiest way to overcome this problem is

by superheating the steam.

Two main variations of the basic Rankine cycle: Rankine cycle with reheat and Regenerative

Rankine cycles.

A Rankine cycle with reheat uses two turbines in series. The first accepts vapor from the boiler at

high pressure. After the vapor has passed through the first turbine, it re-enters the boiler and is

reheated before passing through a second, lower pressure turbine. This prevents the vapor from

condensing during its expansion which can seriously damage the turbine blades, and improves

the efficiency of the cycle.

The other variation is the regenerative Rankine cycle. With this process, the working fluid is

heated by steam tapped from the hot portion of the cycle after emerging from the condenser.

This increases the average temperature of heat addition which in turn increases the

thermodynamic efficiency of the cycle.

A steam turbine consists of a stationary set of blades (called nozzles) and a moving set of

adjacent blades (called buckets or rotor blades) installed within a casing. The two sets of blades





work together such that the steam turns the shaft of the turbine and the connected load. A steam

turbine converts pressure energy into velocity energy as it passes through the blades.

The primary type of turbine used for

central power generation is the

condensing turbine. Steam exhausts

from the turbine at sub-atmospheric

pressures, maximizing the heat

extracted from the steam to produce

useful work. The turbine generator

consists of a series steam turbines

interconnected to each other and a

generator on a common shaft. There is

a high pressure turbine at one end,

followed by an intermediate pressure

turbine, two low pressure turbines,

and the generator. As steam moves

through the system and loses pressure

and thermal energy it expands in

volume, requiring increasing diameter and longer blades at each succeeding stage to extract the

remaining energy. The entire rotating mass may be over 200 tons and 100 feet long. It is so

heavy that it must be kept turning slowly even when shut down so that the shaft will not bow

even slightly and become unbalanced. This is so important that it is one of only five functions of

blackout emergency power batteries on site. Other functions are emergency lighting,

communication, station alarms and turbo-generator lube oil.

Superheated steam from the boiler is delivered through piping to the high pressure turbine where

it falls in pressure to 600 psi and to 320C through the stage. It exits cold reheat lines and passes

back into the boiler where the steam is reheated in special reheat pendant tubes back to 500C.

The hot reheat steam is conducted to the intermediate pressure turbine where it falls in both

temperature and pressure and exits directly to the long-bladed low pressure turbines and finally

exits to the condenser.

To maximize turbine efficiency the steam is expanded, generating work, in a number of stages.

These stages are characterized by how the energy is extracted from them and are known as either

impulse or reaction turbines (See Figure 7). Most steam turbines use a mixture of the reaction

and impulse designs: each stage behaves as either one or the other, but the overall turbine uses

both. Typically, higher pressure sections are impulse type and lower pressure stages are reaction

type.





An impulse turbine has fixed nozzles that

orient the steam flow into high speed jets.

These jets contain significant kinetic

energy, which the rotor blades, shaped

like buckets, convert into shaft rotation as

the steam jet changes direction. A

pressure drop occurs across only the

stationary blades, with a net increase in

steam velocity across the stage.

As the steam flows through the nozzle its

pressure falls from inlet pressure to the

exit pressure (atmospheric pressure, or

more usually, the condenser vacuum).

Due to this higher ratio of expansion of

steam in the nozzle the steam leaves the

nozzle with a very high velocity. The

steam leaving the moving blades has a

large portion of the maximum velocity of

the steam when leaving the nozzle.

In the reaction turbine, the rotor blades themselves are arranged to form convergent nozzles.

This type of turbine makes use of the reaction force produced as the steam accelerates through

the nozzles formed by the rotor. Steam is directed onto the rotor by the fixed vanes of the stator.

It leaves the stator as a jet that fills the entire circumference of the rotor. The steam then changes

direction and increases its speed relative to the speed of the blades. A pressure drop occurs

across both the stator and the rotor, with steam accelerating through the stator and decelerating

through the rotor, with no net change in steam velocity across the stage but with a decrease in

both pressure and temperature, reflecting the work performed in the driving of the rotor.

Feed water heating and de-aeration

The feed water used in the steam boiler is a means of transferring heat energy from the burning

fuel to the mechanical energy of the spinning steam turbine. The total feed water consists of re-

circulated condensate water and purified makeup water. Because the metallic materials it

contacts are subject to corrosion at high temperatures and pressures, the makeup water is highly

purified before use. A system of water softeners and ion exchange de-mineralizers produces

water so pure that it coincidentally becomes an electrical insulator. The make-up water in a





typical plant amounts to perhaps 20 gallons per minute to offset the small losses from steam

leaks in the system.

The feedwater cycle begins with condensate water being pumped out of the condenser after

traveling through the steam turbines. The condensate flow rate at full load may be 6,000 gallons

per minute or more.

The water flows through a series intermediate feedwater heaters, heated up at each point with

steam extracted from an appropriate duct on the turbines and gaining temperature at each stage.

Typically, the condensate plus the makeup water then flows through a deaerator that removes

dissolved air from the water, further purifying and reducing its corrosivity. The water may be

dosed following this point with hydrazine, a chemical that removes the remaining oxygen in the

water. It is also dosed with pH control agents such as ammonia to keep the residual acidity low

and thus non-corrosive.

Figure 5 shows a typical boiler feedwater de-aerator.

Electric Generator

Connected to the steam generator is an electric generator. The generator contains a stationary

stator and a spinning rotor, each containing miles of heavy copper conductor. The rotor spins in

a sealed chamber cooled with hydrogen gas, selected because it has the highest known heat

transfer coefficient of any gas and for its low viscosity which reduces windage losses. This





system requires special handling during startup, with air in the chamber first displaced by carbon

dioxide before filling with hydrogen. This ensures that the highly explosive hydrogen–oxygen

environment is not created.

Steam condensing

The condenser condenses the steam from the exhaust of the turbine into liquid to allow it to be

pumped. If the condenser can be made cooler, the pressure of the exhaust steam is reduced and

efficiency of the cycle increases. The condenser is usually a shell and tube heat exchanger

commonly referred to as a surface condenser. Cooling water circulates through the tubes in the

condenser's shell and the low pressure exhaust steam is condensed by flowing over the tubes as

shown in the adjacent diagram. The tubing is designed to reduce the exhaust pressure, avoid sub-

cooling the condensate and provide adequate air extraction. Typically the cooling water causes

the steam to condense at a temperature of about 30C and that creates a vacuum relative to

atmospheric pressure. The large decrease in volume that occurs when water vapor condenses to

liquid creates the low vacuum that helps pull steam through and increase the efficiency of the

turbines. The limiting factor is the temperature of the cooling water and that, in turn, is limited

by the prevailing average climatic conditions at the power plant's location.

From the bottom of the condenser, powerful condensate pumps recycle the condensed steam – or

water - back to the water/steam cycle.

The heat absorbed by the circulating cooling water in the condenser tubes must also be removed

to maintain the ability of the water to cool as it circulates. This is done by pumping the warm

water from the condenser through either natural draft, forced draft or induced draft cooling

towers that reduce the temperature of the water by evaporation, expelling waste heat to the

atmosphere.

The condenser tubes are made of brass or stainless steel to resist corrosion from either side.

Nevertheless they may become internally fouled during operation by bacteria or algae in the

cooling water or by mineral scaling, all of which inhibit heat transfer and reduce thermodynamic

efficiency. Many plants include an automatic cleaning system that circulates sponge rubber balls

through the tubes to scrub them clean without the need to take the system off-line.

The cooling water used to condense the steam in the condenser returns to its source without

having been changed other than having been warmed. If the water returns to a local water body

(rather than a circulating cooling tower), it is tempered with cool raw water to prevent thermal

shock when discharged into that body of water.





Another form of condensing system is the air-cooled condenser. The process is similar to that of

a radiator and fan. Exhaust heat from the low pressure section of a steam turbine runs through the

condensing tubes, the tubes are usually finned and ambient air is pushed through the fins with the

help of a large fan. The steam condenses to water to be reused in the water-steam cycle. Air-

cooled condensers typically operate at a higher temperature than water cooled versions. While

saving water, the efficiency of the cycle is reduced, which results in more carbon dioxide per

megawatt of electricity.

Cooling tower

Cooling towers are heat removal devices used to transfer process waste heat to the atmosphere.

Cooling towers may either use the evaporation of water to remove process heat and cool the

working fluid to near the wet-bulb air temperature or rely solely on air to cool the working fluid

to near the dry-bulb air temperature.

The primary use of large cooling towers is to remove the heat absorbed in the circulating cooling

water systems used in power plants.

The circulation rate of cooling water in a typical coal-fired power plant with a cooling tower

amounts to about 315,000 gallons per minute and the circulating water requires a supply water

make-up rate of perhaps 5 percent. If that same plant had no cooling tower and used once-

through cooling water, it would require over 400,000 gallons per hour and that amount of water

would have to be continuously returned to the ocean, lake or river from which it was obtained

and continuously re-supplied to the plant. Furthermore, discharging large amounts of hot water

may raise the temperature of the receiving river or lake to an unacceptable level for the local

ecosystem. Elevated water temperatures can kill fish and other aquatic organisms. A cooling

tower serves to dissipate the heat into the atmosphere instead and wind and air diffusion spreads

the heat over a much larger area than hot water can distribute heat in a body of water. Some

coal-fired power plants located in coastal areas do make use of once-through ocean water. But

even there, the offshore discharge water outlet requires very careful design to avoid

environmental problems.

With respect to the heat transfer mechanism employed, the main types are:

• Wet cooling towers or simply cooling towers operate on the principle of evaporation. The

working fluid and the evaporated fluid (usually H2O) are one and the same.

• Dry coolers operate by heat transfer through a surface that separates the working fluid

from ambient air, such as in a heat exchanger, utilizing convective heat transfer. They do

not use evaporation.





In a wet cooling tower, the warm water can be cooled to a temperature lower than the ambient air

dry-bulb temperature, if the air is relatively dry. As ambient air is drawn past a flow of water,

evaporation occurs. Evaporation results in saturated air conditions, lowering the temperature of

the water to the wet bulb air temperature, which is lower than the ambient dry bulb air

temperature, the difference determined by the humidity of the ambient air.

Steam plants use a natural draft process to draw air through the tower. Natural draft utilizes

buoyancy via a tall chimney. Warm, moist air naturally rises due to the density differential to the

dry, cooler outside air. Warm moist air is less dense than drier air at the same pressure. This

moist air buoyancy produces a current of air through the tower.

Hyperboloid cooling towers have become the design

standard for all natural-draft cooling towers because of

their structural strength and minimum usage of material.

The hyperboloid shape also aids in accelerating the

upward convective air flow, improving cooling

efficiency. They are popularly associated with nuclear

power plants. However, this association is misleading,

as the same kind of cooling towers are often used at

large coal-fired power plants as well.

Under certain ambient conditions, plumes of water

vapor (fog) can be seen rising out of the discharge from a cooling tower (, and can be mistaken

as smoke from a fire. If the outdoor air is at or near saturation, and the tower adds more water to

the air, saturated air with liquid water droplets can be discharged—what is seen as fog. This

phenomenon typically occurs on cool, humid days, but is rare in many climates.

Stack gas path and cleanup

As the combustion flue gas exits the boiler it is routed through a rotating flat basket of metal

mesh which picks up heat and returns it to incoming fresh air as the basket rotates, This is called

the air preheater. The gas exiting the boiler is laden with fly ash, which are tiny spherical ash

particles. The flue gas contains nitrogen along with combustion products carbon dioxide, sulfur

dioxide, and nitrogen oxides. The fly ash is removed by fabric bag filters or electrostatic

precipitators. Once removed, the fly ash byproduct can sometimes be used in the manufacturing

of concrete. This cleaning up of flue gases, however, only occurs in plants that are fitted with the

appropriate technology. Still, the majority of coal fired power plants in the world do not have

these facilities.





The sulfur and nitrogen oxide pollutants are removed by stack gas scrubbers which use a

pulverized limestone or other alkaline wet slurry to remove those pollutants from the exit stack

gas. Other devices use catalysts to remove Nitrous Oxide compounds from the flue gas stream.

The gas travelling up the flue gas stack may by this time have dropped to about 50C. A typical

flue gas stack may be 500 feet tall to disperse the remaining flue gas components in the

atmosphere.





Chapter 3

Environmental Issues

Burning coal to create electricity in coal-fired steam plants creates a number of potentially

adverse environmental effects. These effects include:

• Some types of coal mining cause severe erosion, resulting in the leaching of toxic

chemicals into nearby streams and aquifers, and destroys habitants.

• About two-thirds of sulfur dioxide, one-third of carbon dioxide emissions and one quarter

of the nitrogen oxide emissions in the U.S. are produced by coal burning.

• Coal burning also results in the emission of fine particles matter into the atmosphere.

Nitrogen oxide and fine airborne particles exacerbate asthma, reduce lung function and

cause respiratory diseases for thousands of people.

• Smog formed by nitrogen oxide and reactive organic gases cause crop, forest and

property damage. Sulfur dioxide and nitrogen oxides both combine with water in the

atmosphere to create acid rain. Acid rain acidifies the soils and water killing off plants,

fish, and the animals that depend on them.

• Global warming is partially caused by carbon dioxide emissions and is responsible for at

least half of the warming.

Let’s look at a few of the environmental impacts of the coal burning process.

Acid Rain

The combustion of coal contributes the most to acid rain and air pollution, and has been

connected with global warming. Due to the chemical composition of coal there are difficulties in

removing impurities from the solid fuel prior to its combustion. Modern day coal power plants

pollute very little due to new technologies in "scrubber" designs that filter the exhaust air in

smoke stacks. Today, the only pollution caused from coal-fired power plants comes from the

emission of gases—carbon dioxide, nitrogen oxides, and sulfur dioxide into the air. Acid rain is

caused by the emission of nitrogen oxides and sulfur dioxide into the air. These may be only

mildly acidic, yet when they react with the atmosphere, they create acidic compounds (such as

sulfurous acid, nitric acid and sulfuric acid) that fall as rain, hence the term acid rain. In the US

strict emission laws and decline in heavy industries have reduced the environmental hazards

associated with this problem, leading to lower emissions after their peak in 1960s.





Carbon dioxide

Electricity generation using carbon based fuels is responsible for a large fraction of carbon

dioxide (CO2) emissions worldwide and for 41% of U.S. man-made carbon dioxide emissions.

Of fossil fuels, coal combustion in thermal power stations result in the greatest amount of carbon

dioxide emissions per unit of electricity generated – 2,249 lbs/MWh – while oil produces less

at1,672 lb/MWh and natural gas produces the least at 1,135 lb/MWh.

Many believe that carbon dioxide is a greenhouse gas and that increased quantities within the

atmosphere will lead to higher average temperatures on a global scale (global warming).

Emissions may be reduced through more efficient and higher combustion temperature and

through more efficient production of electricity within the cycle. Carbon capture and storage

(CCS) of emissions from coal fired power stations is another alternative but the technology is

still being developed and will increase the cost of fossil fuel-based production of electricity.

Particulate matter

Another problem related to coal combustion is the emission of particulates that have a serious

impact on public health. Power plants remove particulate from the flue gas with the use of a bag

house or electrostatic precipitator.

Particulate matter from coal-fired plants can be harmful and have negative health impacts.

Studies have shown that exposure to particulate matter is related to an increase of respiratory and

cardiac mortality. Particulate matter can irritate small airways in the lungs, which can lead to

increased problems with asthma, chronic bronchitis, airway obstruction, and gas exchange.

There are different types of particulate matter, depending on the chemical composition and size.

The dominant form of particulate matter from coal-fired plants is coal fly ash, but secondary

sulfate and nitrate also comprise a major portion of the particulate matter from coal-fired plants.

Coal fly ash is what remains after the coal has been combusted, so it consists of the

incombustible materials that are found in the coal.

The size and chemical composition of these particles affects the impacts on human health.

Currently coarse and fine particles are regulated, but ultrafine particles are currently unregulated,

yet they may pose dangers. Unfortunately much is still unknown as to which kinds of

particulate matter pose the most harm, which makes it difficult to regulate particulate matter.





There are several methods to help to reduce the particulate matter emissions from coal-fired

plants. Roughly 80% of the ash falls into an ash hopper, but the rest of the ash then gets carried

into the atmosphere to become coal-fly ash. Methods of reducing these emissions of particulate

matter include: a baghouse, an electrostatic precipitator, and a cyclone collector.

The baghouse has a fine filter that collects the ash particles, electrostatic precipitators use an

electric field to trap ash particles on high-voltage plates, and cyclone collectors use centrifugal

force to trap particles to the walls.

Mountain Top Removal

Environmentalist claim that mountaintop mining has serious environmental impacts, including

loss of biodiversity, and adverse human health impacts which result from contact with affected

streams or exposure to airborne toxins and dust.

Mountain top removal mining (MTR), also known

as mountaintop mining is a form of surface mining

that involves the mining of the summit ridge of a

mountain. Entire coal seams are removed from the

top of a mountain, hill or ridge by removing the

overburden (soil, lying above the economically

desired resource). After the coal is extracted, the

removed material is put back onto the ridge to

approximate the mountain's original contours.

Any overburden that cannot be put back onto the ridge top is moved into neighboring valleys.

Mountaintop removal is most closely associated with coal mining in the Appalachian Mountains

in the eastern United States.

Environmentalist claim that mountaintop mining has serious environmental impacts, including

loss of biodiversity, and adverse human health impacts which result from contact with affected

streams or exposure to airborne toxins and dust.

The MTR process involves the removal of coal seams by first fully removing the overburden

lying atop them, exposing the seams from above. This method differs from more traditional

underground mining, where typically a narrow shaft is dug which allows miners to collect seams

using various underground methods, while leaving the vast majority of the overburden

undisturbed. The overburden waste resulting from MTR is either placed back on the ridge,

attempting to reflect the approximate original contour of the mountain, and/or it is moved into

neighboring valleys.





The process involves blasting to remove overburden to expose underlying coal seams. Excess

rock and soil laden with mining byproducts are often moved into nearby valleys, in what are

called "holler fills" or "valley fills."

Mountaintop removal has been practiced since the 1960s. Increased demand for coal in the

United States, sparked by the petroleum crises in the 1970’s, created incentives for a more

economical form of coal mining than the traditional underground mining methods involving

hundreds of workers, triggering the first widespread use of MTR. Its prevalence expanded

further in the 1990s to retrieve relatively low-sulfur coal, a cleaner-burning form, which became

desirable as a result of amendments to the U.S. Clean Air Act that tightened emissions limits on

high-sulfur coal processing.

The coal industry asserts that surface mining techniques, such as mountaintop removal, are safer

for miners than sending them underground.

Proponents argue that in certain geologic areas, MTR and similar forms of surface mining allow

the only access to thin seams of coal that traditional underground mining would not be able to

mine. MTR is sometimes the most cost-effective method of extracting coal.

Critics contend that MTR is a destructive and unsustainable practice that benefits a small number

of corporations at the expense of local communities and the environment. Though the main issue

has been over the physical alteration of the landscape, opponents to the practice have also

criticized MTR for the damage done to the environment by massive transport trucks, and the

environmental damage done by the burning of coal for power. Blasting at MTR sites also expels

dust and fly-rock into the air, which can disturb or settle onto private property nearby. This dust

may contain sulfur compounds, which corrodes structures and is a health hazard.

Advocates of MTR claim that once the areas are reclaimed - as mandated by law - the area can

provide flat land suitable for many uses in a region where flat land is at a premium. They also

maintain that the new growth on reclaimed mountaintop mined areas is better suited to support

populations of game animals.

Carbon Sequestration

There are generally three ways to manage carbon emissions,

1. Reduce the need for fossil fuel combustion through increased energy efficiency.

2. Use alternative low-carbon and carbon-free fuels and technologies such as nuclear power

and renewable sources.





3. Capture and securely store carbon emitted from the fossil fuel combustion, which is

known as carbon sequestration.

The purpose of carbon sequestration is to keep carbon emissions from reaching the atmosphere

by capturing them, isolating them, and diverting them to secure storage. Any viable system for

sequestering carbon must be safe, environmentally benign, effective, and economical. In

addition, it must be acceptable to the public.

Several available technologies are used to separate and capture CO2 from fossil-fueled power

plant flue gases. The use of existing technology for removing CO2 is projected to raise the cost

of producing electrical power from coal-fired power plants. Although CO2 is separated

routinely, dramatic improvements are necessary to make the process economical. Techniques are

needed to transform the captured CO2 into materials that can be economically and safely

transported and sequestered for a long time.

There are numerous options for the separation and capture of CO2, and many of these are

commercially available. However, none has been applied at the scale required as part of a CO2

emissions mitigation strategy. Many issues remain regarding the ability to separate and capture

CO2 from sources on the scale required, and to meet the cost, safety, and environmental

requirements for separation and capture. The three most promising methods of carbon storage

include:

• Ocean sequestration,

• Terrestrial ecosystem sequestration, and

• Geologic formation sequestration.

There are many technological issues to resolve before carbon sequestration will be a viable

environmental option.

Geologic Sequestration

Three principal types of geologic formations are widespread in the United States and have the

potential for sequestering large amounts of CO2. They are active and uneconomical oil and gas

reservoirs, aqueous formations, and deep coal formations. Presently about 70 oil fields

worldwide use injected CO2 for enhanced oil recovery. The United States has sufficient

capacity, diversity, and broad geographic distribution of potential reservoirs to use geologic

sequestration in the near term. The primary uncertainty is the effectiveness of storing CO2 in

geological formations - how easily CO2 can be injected and how long it will remain. Many

important issues must be addressed to reduce costs, ensure safety, and gain public acceptance.





Geologic formations, such as oil fields, coal beds, and aquifers, are likely to provide the first

large scale opportunity for concentrated sequestration of CO2. Developers of technologies for

sequestration of CO2 in geologic formations can draw from related experience gained over nearly

a century of oil and gas production, groundwater resource management, and, more recently,

natural gas storage and groundwater remediation. In some cases, sequestration may even be

accompanied by economic benefits such as enhanced oil recovery, enhanced methane production

from coal beds, enhanced production of natural gas from depleted fields, and improved natural

gas storage efficiency through the use of CO2 as a “cushion gas” to displace methane from the

reservoir.

CO2 can be sequestered in geologic formations by three principal mechanisms. First, CO2 can be

trapped as a gas or supercritical fluid under a low-permeability caprock, similar to the way that

natural gas is trapped in gas reservoirs or stored in aquifers. This mechanism, commonly called

hydrodynamic trapping, will likely be the most important for sequestration. Finding better

methods to increase the fraction of space occupied by trapped gas will enable maximum use of

the sequestration capacity of a geologic formation.

Second, CO2 can dissolve into the fluid phase. This mechanism of dissolving the gas in a liquid

such as petroleum is called solubility trapping. In oil reservoirs, dissolved CO2 lowers the

viscosity of the residual oil so it swells and flows more readily, providing the basis for one of the

more common oil recovery techniques. The relative importance of solubility trapping depends

on a large number of factors, such as the sweep efficiency of CO2 injection, the formation of

fingers (preferred flow paths), and the effects of formation heterogeneity. Efficient solubility

trapping will reduce the likelihood that CO2 gas will quickly return to the atmosphere.

Finally, CO2 can react either directly or indirectly with the minerals and organic matter in the

geologic formations to become part of the solid mineral matrix. In most geologic formations,

formation of calcium, magnesium, and iron carbonates is expected to be the primary mineral

trapping processes. However, precipitation of these stable mineral phases is a relatively slow

process with poorly understood kinetics. In coal formations, trapping is achieved by preferential

adsorption of CO2. Developing methods for increasing the rate and capacity for mineral trapping

will create stable repositories of carbon that are unlikely to return to the biosphere and will

decrease unexpected leakage of CO2 to the surface.

To sequester CO2 produced from the combustion of fossil fuels to generate electricity, CO2 needs

to be separated from the waste stream to a purity of at least 90%. CO2 is then transported as a

supercritical fluid by pipeline to the nearest geologic formation suitable for sequestration. The

cost for transportation will likely be significant.

Ocean Sequestration





The ocean represents a large potential storage location for carbon dioxide. One solution is to

inject a relatively pure CO2 stream that has been generated by a power plant directly into the

deep ocean. The injected CO2 may become trapped in ocean sediments or ice-like solids, called

hydrates. Another option is to increase the net oceanic uptake from the atmosphere by enhancing

the ocean ability to absorb CO2 with iron fertilization. Active experiments are already under way

in iron fertilization and other tests of enhanced marine biological sequestration, as well as deep

CO2 injection. These approaches will require better understanding of marine ecosystems to

enhance the effectiveness of applications and avoid undesirable consequences.

The ocean represents a large potential sink for sequestration of CO2 emissions, although the

long-term effectiveness and potential side effects of using the oceans in this way are unknown.

There are two primary methods of enhancing ocean sequestration,

• The direct injection of CO2

• Enhancement of the natural ocean uptake from the atmosphere

For a given option the tradeoffs among cost, long-term effectiveness, and changes to the ocean

ecosystem are discussed.

On average, the ocean is about 13,000 feet deep and contains 40,000 GtC of CO2. It is made up

of a surface layer (nominally 300 feet thick), a thermocline (down to about 3,000 feet deep) that

is stably stratified, and the deep ocean below 3,000 feet. Its waters circulate between surface and

deep layers on varying time scales from 250 years in the Atlantic Ocean to 1,000 years for parts

of the Pacific Ocean. The amount of carbon that would cause a doubling of the atmospheric

concentration would change the deep ocean concentration by less than 2%.

On a time scale of 1,000 years, about 85% of today’s emissions of CO2 will be transferred to the

ocean. The strategy with ocean sequestration is to attempt to speed up this process to reduce

both peak atmospheric CO2 concentrations and their rate of increase.

Terrestrial Sequestration

Terrestrial ecosystems, which are made up of vegetation and soils containing microbial and

invertebrate communities, sequester CO2 directly from the atmosphere. The terrestrial

ecosystem is essentially a huge natural biological scrubber for CO2 from all fossil fuel emissions

sources, such as automobiles, power plants, and industrial facilities. The ability of the ecosystem

to sequester carbon can be significantly increased over the next few years to provide a critical

“bridging technology” while other carbon management options are developed. The potential for

terrestrial ecosystems to remove and sequester more carbon from the atmosphere could be

increased by, for example, improving agricultural cultivation practices to reduce oxidation of soil

carbon and enhancing soil texture to trap more carbon, and protecting wetlands.





The terrestrial biosphere is another potential avenue for sequestering carbon. The aim of

developing enhanced carbon sequestration in the biosphere is to enable a rapid gain in

withdrawal of CO2 from the atmosphere over the next 50 years in order to allow time for

implementation of other technological advances that will help mitigate CO2 emissions.

Carbon sequestration in terrestrial ecosystems is either the net removal of CO2 from the

atmosphere or the prevention of CO2 net emissions from terrestrial ecosystems into the

atmosphere. Carbon sequestration may be accomplished by increasing photosynthetic carbon

fixation, reducing decomposition of organic matter, reversing land use changes that contribute to

global emissions, and creating energy offsets through the use of biomass for fuels or beneficial

products. The latter two methods may be viewed more appropriately as carbon management

strategies.

The terrestrial biosphere is estimated to sequester large amounts of carbon, on the order of two

GtC/year. There are two fundamental approaches to sequestering carbon in terrestrial

ecosystems: protection of ecosystems that store carbon so that sequestration can be maintained

or increased and manipulation of ecosystems to increase carbon sequestration beyond current

conditions. In this section, we will review the inventories of carbon in terrestrial ecosystems and

the roles of the biosphere in the global sequestration process and then estimate the potential for

carbon sequestration in each of them.

Carbon sequestration in terrestrial ecosystems will provide significant near-term benefits with

the potential for even more major contributions in the long-term. There are many ancillary

positive benefits from carbon sequestration in terrestrial ecosystems, which are already a major

biological scrubber for CO2. The potential for carbon sequestration could be large for terrestrial

ecosystems (5–10 GtC/year). However, this value is speculative, and research is needed to

evaluate this potential and its implications for ecosystems.





Summary

Coal-fired steam plants have been a cornerstone of electric power generation for over 100 years

and will continue to be a major fuel source for many years to come. At the current burn rates

known coal reserves will last for centuries.

Coal has significant environmental and societal issues. Improving efficiencies in coal-fired

power plant operation as well as improved environmental controls may help coal to remain a

viable fuel source. If the promise of carbon sequestration comes to pass, then coal-fired steam

plants may remain as one of the lowest cost generation sources for several hundred years.

Copyright © 2020 Lee Layton. All Rights Reserved.

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DISCLAIMER: The material contained in this course is not intended as a representation or warranty on the part

of the Provider or Author or any other person/organization named herein. The material is for general

information only. It is not a substitute for competent professional advice. Application of this information to a

specific project should be reviewed by a relevant professional. Anyone making use of the information set forth

herein does so at his own risk and assumes any and all resulting liability arising therefrom.



Documents

Coal Fired Steam Plants - PDHonline.comThe coal is crushed between balls or cylindrical rollers that move between two tracks or "races." The raw coal is then fed into the pulverizer